Asphaltene fractions are conventionally defined as the portion of crude oil or bitumen which precipitates on addition of a low molecular weight paraffin, typically n-pentane or n-heptane, but which is soluble in toluene. Asphaltenes are amorphous solids having a complex structure formed of condensed aromatic nuclei associated with alicyclic groups and involve carbon, hydrogen, nitrogen, oxygen and sulfur. The asphaltene particles are typically surrounded by naturally occurring resins which are thought to provide some dispersion stability.
Asphaltenes are typically present in crude oils and are largely stable in their native formation. Crude oil is conventionally described as a colloidal system which is stabilized to some extent by the naturally occurring resins which act as peptizing agents. Changes in pressure, temperature and phase composition however may result in destabilization and deposition, such as precipitation, of the asphaltenes in the formation. Such deposition may have catastrophic effects on the recovery of the crude from the formation. Destabilization and deposition of the aggregated asphaltene particles on the surface of, or in the pores in, the reservoir results in a loss of permeability and often significant reduction in production therefrom. Once blocked, efforts to remove the deposited asphaltene, using solvents such as toluene and the like, may be only minimally successful, are costly and present environmental hazards.
Fluids, including non-aqueous hydrocarbon or synthetic fluids or mixtures thereof, aqueous fluids and liquid CO2 which are used in the petroleum industry may enter the reservoir through injection, such as in hydraulic fracturing, or may leak into the reservoir during drilling and the like. The presence of fluids, into the reservoir, whether injected or leaked, is understood in the industry to be problematic as the balance between the constituents of the native crude is readily upset, leading to asphaltene deposition. It is generally taught in the industry to avoid the use of a large variety of additives to fluids which are used directly in the formation or which may enter the formation, as it is thought that the nature of many additives, including those conventionally used for asphaltene control in already produced fluids, may lead to asphaltene deposition and the resultant damage to the formation. Further, it is also thought to be highly problematic to use fluids which contain aliphatics as the industry believes that aliphatics will also cause formation damage though asphaltene deposition.
Hydraulic fracturing of a reservoir is a production stimulation technique which utilizes volumes of fluid flowed into the reservoir, typically under pressure. Some fracturing fluids contains a proppant, such as sand, to support opened fractures within the reservoir to increase the permeability therein. A formation may be subjected to hydraulic fracturing techniques at the beginning of its production life or may be fractured one or more times later when readily available hydrocarbons have been removed and production begins to decrease or the reservoir is thought to be damaged. The influx of said hydraulic fracturing fluids into the wellbore may upset the nature of the colloidal system and result in the deposition of asphaltenes depending upon the nature of the crude, the characteristics of the reservoir and the nature of the fluids used for fracturing.
Conventional fracturing fluids typically contain few additives. Those additives which are typically added are generally only used to control the viscosity of the fluid, such as a gelling agent, which causes the viscosity of the fluid to increase so that proppant is retained in the fluid during fracturing. Typically, the fluids are designed to “break” or revert to a less viscous fluid following fracturing so as to deposit the proppant therein for keeping the fractures open during production. Cross-linking agents and breaking agents are added to help formation of the gel and breaking of the gel when so desired.
It is well known in the industry to use aromatic fluids, or fluids that have a relatively high aromatic content, as fracturing fluids. Typically, asphaltenes are more readily dispersed in aromatic fluids and therefore thought to be less likely to affect the permeability of the formation. Aromatic fluids suitable for this purpose generally contain large amounts of benzene, toluene and xylene (BTEX) or polycyclic aromatic hydrocarbons (PAH) which are carcinogenic and environmentally hazardous. Thus, it is desirable, when possible, to find alternatives to the use of significant amounts of aromatics when fracturing. This is particularly true in the case of sensitive off-shore environments.
Use of more environmentally friendly aliphatic fluids or blends of aromatic and aliphatic fluids containing large portions of aliphatics to replace fluids containing largely aromatics is, as previously stated, generally regarded in the industry to be problematic, as aliphatic fluids typically initiate deposition of asphaltene when in contact with native crude oils in the formation.
Applicant is aware that in some cases, even with conventional fracturing fluids, that the industry recommends performing core sample tests prior to fracturing on each and every formation to ensure that the fracturing fluid is compatible with the unique formation. Testing of this nature is time consuming and relatively expensive and delays production.
Liquid CO2, which can be used for fracturing and the like, has a number of advantages, such as its ability to break down carbonaceous formations as well as its ability to be injected in the liquid state and return to a gaseous state near surface. The industry however is reluctant to use CO2 as it is thought, in many cases, to enhance asphaltene deposition within the formation and reduce production therefrom.
Thus, there is much interest in the industry for the development of environmentally friendly fluids such as fracturing fluids and drilling fluids which minimize asphaltene deposition while at the same time avoiding interfering with the function and effectiveness of other fluid additives such as conventional gelling, cross-linking and breaking agents. Further, there is an interest in finding fluids that can be universally applied to any formation without the need to perform specialized and expensive testing at each wellsite.